Hydraulic fracturing of subterranean formations has long been established as an effective means to stimulate the production of hydrocarbon fluids from a wellbore. In hydraulic fracturing, a well stimulation fluid (generally referred to as a fracturing fluid) is injected into and through a wellbore and against the surface of a subterranean formation penetrated by the wellbore at a pressure at least sufficient to create a fracture in the formation. Usually a “pad fluid” is injected first to create the fracture and then a fracturing fluid, often bearing granular propping agents, is injected at a pressure and rate sufficient to extend the fracture from the wellbore deeper into the formation. If a proppant is employed, the goal is generally to create a proppant filled zone from the tip of the fracture back to the wellbore. In any event, the hydraulically induced fracture is more permeable than the formation and it acts as a pathway or conduit for the hydrocarbon fluids in the formation to flow to the wellbore and then to the surface where they are collected.
The fluids used as fracturing fluids have also been varied, but many if not most are aqueous based fluids that have been “viscosified” or thickened by the addition of a natural or synthetic polymer (crosslinked or uncrosslinked) or a viscoelastic surfactant. The carrier fluid is usually water or a brine (e.g., dilute aqueous solutions of sodium chloride and/or potassium chloride).
The viscosifying polymer is typically a solvatable (or hydratable) polysaccharide, such as a galactomannan gum, a glycomannan gum, or a cellulose derivative. Examples of such polymers include guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, polyacrylamides and other synthetic polymers. Of these, guar and hydroxypropyl guar are typically preferred because of commercial availability and cost performance.
In many instances, if not most, the viscosifying polymer is crosslinked with a suitable crosslinking agent. The crosslinked polymer has an even higher viscosity and is even more effective at carrying proppant into the fractured formation. The borate ion has been used extensively as a crosslinking agent, typically in high pH fluids, for guar, guar derivatives and other galactomannans. Other crosslinking agents include, for example, titanium, chromium, iron, aluminum, and zirconium.
Viscoelastic surfactant fluids are normally made by mixing into the carrier fluid appropriate amounts of suitable surfactants such as anionic, cationic, nonionic and zwitterionic surfactants. The viscosity of viscoelastic surfactant fluids is attributed to the three dimensional structure formed by the components in the fluids. When the concentration of viscoelastic surfactants significantly exceeds a critical concentration, surfactant molecules aggregate into micelles, which can become highly entangled to form a network exhibiting elastic behavior.
Viscoelastic surfactant solutions are usually formed by the addition of certain reagents to concentrated solutions of surfactants, frequently consisting of long-chain quaternary ammonium salts such as cetyltrimethylammonium bromide (CTAB). Common reagents that generate viscoelasticity in the surfactant solutions are salts such as ammonium chloride, potassium chloride, sodium salicylate and sodium isocyanate and non-ionic organic molecules such as chloroform. The electrolyte content of surfactant solutions is also an important control on their viscoelastic behaviour.
A key aspect of well treatment such as hydraulic fracturing is the “cleanup”, e.g., removing the carrier fluid from the fracture (i.e., the base fluid without the proppant) after the treatment has been completed. Techniques for promoting fracture cleanup often involve reducing the viscosity of the fracture fluid as much as practical so that it will more readily flow back toward the wellbore.
Gel breakers are of common use for conventional polymer based fluids used in stimulation and the like since, unlike viscoelastic surfactant based fluids, conventional polymer-based fluids do not spontaneously break when contacted by hydrocarbons or aqueous formation fluids and leaving a high viscosity fluid in the formation would result in a reduction of the formation permeability and, consequently, a decrease of the production. The most widely used breakers are oxidizers and enzymes. The breakers can be dissolved or suspended in the liquid (aqueous, non-aqueous or emulsion) phase of the treating fluid and exposed to the polymer throughout the treatment (added “internally”), or exposed to the fluid at some time after the treatment (added “externally”).
The most common external methods and compositions involve encapsulated enzymes or encapsulated oxidizers or involve the use of pre- or post-flushes that contain breakers. Breaking can occur in the wellbore, gravel pack, filter cake, the rock matrix, in a fracture, or in another added or created environment. See, for example, U.S. Pat. No. 4,741,401 (Walles et al.), assigned to Schlumberger Dowell and incorporated herein by reference.
Though viscoelastic-based fracturing fluids are spontaneously broken by hydrocarbon fluids contained in the formation fluids, it is sometimes suitable to better control the breaking. In U.S. patent application Ser. No. 09/826,127, published Jan. 10, 2002 under number 20020004464, incorporated herein by reference, several types of breakers are proposed including encapsulated salts such as ammonium persulfate, sodium salicylate, inorganic salts such as NaPF6 (sodium hexafluorophosphate) and KCl (potassium chloride).
Several mechanisms are typically involved in the release of an encapsulated material. Those mechanisms typically involve partial dissolution of the capsule enclosures, osmotic or chemical diffusion. However, since it is suitable that the breaking occurs no later than at the end of the fracturing operation, when the fracture closes due to formation pressure, a key mechanism is the release of the breaking agent through the rupture of the enclosure or encapsulating coating. Obviously, the bigger the capsules, the higher their probability of being crushed during the fracture closure. On the other hand, the encapsulated breaker has to be pumped downhole and therefore, as a rule, the size of the capsules of breakers is chosen similar to the size of the proppant.
The most commonly used proppant is made of sand grains having a size ranging between about 0.1 mm and about 2 mm, and most commonly between 0.2 mm and 0.5 mm. Therefore, when a new material is studied to determine its suitability as an encapsulated breaker, a crucial limitation is its availability as granules with sufficient strength to survive the encapsulation process. Many solid materials are actually only available in powder form, passing through a sieve having an opening corresponding to 250 mesh according to the ASTM standard, or in other words, consisting of particles mostly ranging between 0.03 mm and 0.05 mm.
It should be further emphasized that even if the principal mechanism of release of breaking agent that is contemplated is not through crushing due to fracture closure but for instance, through dissolution or leakage of the enclosure; for an effective encapsulation almost all particles have to be coated to prevent failure of the whole fracturing operation. Coating a powder-like material usually results in some particles being uncoated or incompletely coated, at least using affordable technologies. Therefore, the breaking agent prematurely reacts with the crosslinked polymers so that the fluid may lose its suspending properties well before the proppant is properly placed in the fracture.
In the context of other fluid used in well services operations, such as cementing fluids, delayed release of some additives such as accelerators is also suitable. Though the particle size is not as critical as for fracturing fluids, it would be advantageous to be able to deliver some additives in encapsulated form.
The need for improved well services fluids still exists, and the need is met at least in part by the following invention.